Wellbores are drilled in geological formations using a drill rig supporting a drill bit. In order to help in the drilling, drilling mud is circulated from the surface of the formation to the drill bit, and the mud with the cuttings from the formation is brought to the surface for disposal. The drilling mud can be a water based mud, an oil based mud (OBM), or a synthetic based mud (SBM). After the wellbore has been drilled it is common for mudcake to line the wellbore.
In determining the nature of the fluid (oil) in the formation for purposes of producing oil, it is common to place tools into the wellbore and against the formation to obtain formation fluid samples. For example, the Modular Formation Dynamics Tester™ (MDT) tool of Schlumberger may be used to collect formation fluid samples and bring them to the surface for laboratory analysis. The MDT tool is located in the wellbore and a pressure seal is made with the formation reservoir via a retractable hydraulically activated probe head. Onboard pumps then draw fluid into a flow line inside the tool body. Often, upon initial drawing of fluid into the flow line, the reservoir fluids are contaminated by the drilling fluids (e.g., OBM or SBM) mixed with the mud. To ensure that the samples collected have low levels of contamination, an optical port is placed in the flow line and the fluid is monitored using near infrared (NIR) spectroscopy. Nonetheless, samples are sometimes brought to the surface with high levels of drilling fluid contamination. This can happen when there is formation water that is mixed by the action of the pumps and forms a stable emulsion. The scatter from the emulsion water droplets compromises the absorption measurement and the samples are collected blindly, so there is a reasonable probability that an unacceptably high contamination level will exist. This can also happen when the near infrared spectral fingerprint of the oil in the drilling fluid overlaps the near infrared spectral fingerprint of the formation oil. Regardless, collection and use of contaminated samples is not desirable as it may lead to incorrect analysis of the formation fluid resulting in less than optimal determinations regarding production.
The standard laboratory technique for determining contamination levels is through use of a gas chromatography (GC) subtraction method. In this method, components of the sampled fluid are separated according to GC retention time. In favorable cases, peaks in the GC chromatogram resulting from investigation of the drilling fluid can be resolved, identified and quantified, and then the level of contamination can be estimated by comparing the intensity of the drilling fluid peak with the intensity of an internal standard. However, this method suffers when components of the drilling fluid cannot be separated from components of the petroleum by GC, as is common in heavy oils, biodegraded oils, or water washed oils.